As is well known in the art, oil field collection tanks are used as loading points for oil collected from conventional heavy and mid to light crude oil wells. The field collection tanks allow the operator to have a mixture including crude oil (as hereinafter described) flow from the subsurface formation, via the well, to the Earth's surface (i.e., the collection tanks) at a natural flow rate, or at a pump-assisted flow rate. The mixture accumulates in the tank until sufficient volume is in the tank to trigger level instrumentation inside the tank, which then signals that the volume of accumulated crude oil has reached a predetermined level. Typically, a tanker is then sent to the site in response to the signal to remove the accumulated crude oil from the collection tank. The oil is transported by the tanker to larger storage tanks, where it is stored until processed.
Typically, the crude oil accumulates in the collection tank over an extended period of time, e.g., several days, before a volume sufficient to cause the signals to be sent that request the tanker to remove crude oil from the collection tank.
The mixture that flows from the subsurface formation usually includes water and sediment. (“Sediment” herein refers to all foreign (non-crude oil) material other than water in the mixture.) Where the crude oil is heavy crude oil, it is desirable that the mixture that accumulates in the collection tank be treated (i.e., “conditioned”) while it is in the collection tank, to separate at least part of the water and sediment from the crude oil. Such separation permits more efficient processing of the crude oil subsequently.
The treatment, or conditioning, involves maintaining the crude oil at an elevated temperature (e.g., approximately 80° C.). Due to such conditioning, over a relatively short time period, the water and sediment separate from the heavy crude oil, and stratify, i.e., they also substantially separate from each other. As is known in the art, the heat facilitates the separation of the heavy crude oil, the water, and the sediment, under the influence of gravity. The heat reduces the viscosity of the heavy crude oil sufficiently to permit the sediment to separate from the crude oil, under the influence of gravity. The separation of the crude oil from the water and sediment typically begins upon introduction of the mixture into the container. However, in order for the separation (i.e., the conditioning) to be substantially completed, it appears that the mixture needs to reach a temperature of approximately 80° C.
FIG. 1A is a cross-section of a collection tank 10 of the prior art showing, for purposes of illustration, a mixture 12, i.e., prior to conditioning thereof. In FIG. 1B, the results of the conditioning are shown. (As will be described, the remainder of the drawings illustrate the present invention.) Due to the conditioning, the mixture 12 shown in FIG. 1A has separated into heavy crude oil 14 positioned above water 16 and sediment 18. Those skilled in the art would appreciate that the mixture as shown in FIG. 1A, and the stratification of the mixture as shown in FIG. 1B, are somewhat simplified for the purposes of illustration. In FIG. 1A, a surface 19 of the mixture 12 is identified. In FIG. 1B, a surface of the heavy crude oil 14 is identified by reference numeral 19′ for clarity.
Because of the conditioning, the water and sediment are generally separated from the heavy crude oil in the collection tank. Having a density of about 0.92 g/cc (57.4 lbs./cu. ft.), the heavy crude oil is less dense than the water and the sediment. Accordingly, once the mixture has been conditioned, the water and the sediment are separated, and positioned below the heavy crude oil so that the tanker can remove only the “conditioned” crude portion to the processing facility (FIG. 1B). As is well known in the art, after the heavy crude oil is removed, the accumulated water and sediment are removed separately.
In practice, where an oil well produces crude oil at a relatively rapid rate, the mixture may not be allowed to remain in the container long enough to reach the desired conditioning temperature of 80° C. In this situation, due to the relatively small capacity of the container in view of the well's production rate, the crude oil is removed from the container of necessity, however, the removal may take place before the preferred temperature of 80° C. is achieved. One consequence of this is that the viscosity of the crude oil is relatively high while it is in the container, and for this reason, smaller pieces of sediment remain trapped in the crude oil. That is, if the mixture doesn't remain in the container long enough to reach 80° C., the conditioning is not completed. These trapped impurities ultimately result in higher processing costs.
Existing field collection tank designs typically include thermal insulation on the outside of the tank and a source of heat (e.g., a gas-fired direct burner heater) (not shown in FIGS. 1A and 1B) mounted on the field tank to maintain the mixture's temperature at, or close to, the ideal temperature of approximately 80° C. which is required for oil conditioning during accumulation. However, because the desired temperature is elevated, heat is lost from the mixture to the surroundings. Accordingly, one disadvantage of the prior art is that the heat loss results in increased operational costs, due to energy inputs required for additional heat, to replace the heat lost to the surroundings.
As noted above, another disadvantage of the prior art is that, when the crude oil production rate requires that the container be emptied relatively frequently, the mixture is not properly heated (i.e., to 80° C.) before the heavy crude oil is removed.
Much of the heat loss from the mixture is from the surface thereof, partially (but not entirely) due to vapours escaping therefrom. The vapours contain many light hydrocarbon compounds, generally known in the industry as BTEX. These vapours contain carcinogens and therefore pose a health risk. Also, their escape from the collection tank is a vehicle for the loss of a great deal of thermal energy. As is well known in the art, the collection tanks are not pressure vessels and are vented to the atmosphere, to allow the liquid level to change without causing a pressure or vacuum condition to occur. In FIGS. 1A and 1B, vapours and thermal energy escape from the collection tank via the headspace “H” as schematically indicated by arrow “A”. Accordingly, the escape of such vapours from the container is another disadvantage of the prior art.
Depending upon the oil well, there may be natural gas and other vapours that percolate up in the mixture in the collection tank, and these gases can cause the mixture (or, after separation, the heavy crude oil) to froth. This oil froth or foam, which can become relatively thick in elevation above the actual liquid surface, can cause the liquid level instrumentation to generate a false high level indication and prematurely shut down the oil well pump prior to the field tank actually being full. To prevent this, current practice is to employ chemical surfactant additives via dosing systems at each of the well locations, to administer the chemical surfactants into the flow of the mixture that will reduce frothing inside the storage tanks. However, the chemical surfactants also contain BTEX and carcinogenic chemicals that are undesirable, and consequently put operators at risk.
Also, the chemical surfactant additives, by their nature, reduce the heat transfer efficiency of any thermal equipment that comes into contact with the heavy crude oil, thereby making heat transfer processes less energy efficient. That is, because surfactants reduce surface tension, their use tends to result in more laminar flow, i.e., correspondingly less turbulent flow. Because energy transfer to the liquid is more efficient where the liquid is subject to turbulent flow, the use of surfactants generally tends to result in less efficient transfers of energy, e.g., heat energy. Accordingly, elimination of the chemical surfactant additives would be advantageous, because it would save costs, increase thermal efficiency and eliminate certain health risks to operators.
Floating segmented covers are known that typically are made from recycled polypropylene/high-density polyethylene (HDPE) or polyethylene (PE) that is chemically foamed to a specific gravity of at least 0.5 (i.e., a density of not less than 0.5 g/cc (approximately 31.2 lbs./cu. ft.)). This density is due to the nature of the material and technical and processing limitations, as is known in the art. These covers are made of several cover components and are only intended for water and wastewater applications, where the specific gravity of the fluid covered is approximately 1.0. With a specific gravity of 0.5 (i.e., a density of approximately 0.5 g/cc (approximately 31.2 lbs./cu. ft.)) these prior art cover components initially can float on the surface of an aqueous liquid with the liquid waterline positioned substantially at the center of the cover component. For instance, the wastewater may include manure, and the cover is intended to impede and obstruct the release of noxious odours and potentially harmful vapours from the wastewater.
However, it has been found that, over time, the prior art cover components absorb and/or adsorb water into the cellular structure of the foamed polymer. They therefore become heavier (i.e., more dense) over time. When the specific gravity of the cover component is greater than 0.5 (i.e., a density of 0.5 g/cc (approximately 31.2 lbs./cu. ft.)), the liquid level is above the vertical center of the cover component, i.e., allowing liquid to be above at least part of the cover component. At that point, the cover components are no longer covering the surface of the wastewater, and the odours and vapours escape from the wastewater. It can be seen, therefore, that the prior art foamed polypropylene, HDPE, or PE cover components are effective for only a limited period of time when they are used on water.
The prior art foamed polypropylene covers have been tested in the heated (or “conditioned”) mixture of heavy crude oil, water, and sediment described above. Such prior art covers have been found to be unsatisfactory in this context, for a number of reasons. In particular, the prior art covers tend to sink within a relatively short time after being positioned on the heated mixture. Based on the testing done to date, it appears that there are at least three distinct reasons why the prior art covers do not function properly when positioned in and on the mixture in the collection tank.
First, the density of the prior art cover components is too high. The a hydrocarbon liquid mixture typically has a specific gravity of about 0.8-0.9 (i.e., a density of about 0.8-0.9 g/cc (approximately 49.9-56.2 lbs./cu. ft.)). In order for the cover component to be less than about 50 percent submerged initially, the prior art cover component would need a specific gravity less than about 0.5 (i.e., a density of less than about 0.5 g/cc (approximately 31.2 lbs./cu. ft.)). Accordingly, the prior art cover components tend to sink when positioned on the mixture. Due to the configuration of the cover components (i.e., generally wider in the middle), when the cover component is more than about 50 percent submerged, the mixture is on top of at least part of the cover component, and the cover components do not substantially cover the surface.
Second, it is believed that the heavy crude oil is relatively quickly absorbed and/or adsorbed into the foamed cellular structure of the prior art cover components. The prior art chemically foamed polymer cover components, made of polypropylene or polyethylene (as described above), appear to allow the diffusion of hydrocarbons and water through the cellular structure of the polymer wall thereof relatively quickly. This causes the prior art cover component to gain weight relatively quickly and sink further into the liquid, quickly rendering it largely submerged and ineffective.
Third, the prior art foamed polypropylene, HDPE, and PE cover components are not chemically compatible with the hydrocarbons, i.e., these materials are soluble in hydrocarbons. In particular, the elevated operating temperatures encountered in the crude oil collection tanks tend to accelerate the polypropylene, HDPE, and PE degradation.